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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
Commission File Number 33-83618
SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)
Delaware
51-0324332
(State or other jurisdiction of
(I.R.S. Employer Identification Number)
incorporation or organization)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware
51-0354675
(State or other jurisdiction of
(I.R.S. Employer Identification Number)
incorporation or organization)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 788-3000
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OR 12 (g) OF THE ACT:
None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __
As of November 13, 2002, there were 10 shares of common stock of Selkirk
Cogen Funding Corporation, $1 par value outstanding.
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TABLE OF CONTENTS
Page
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of September 30, 2002
and December 31, 2001....................................... 1
Consolidated Statements of Operations for the three and nine
months ended September 30, 2002 and 2001................... 2
Consolidated Statements of Cash Flows for the three and nine
months ended September 30, 2002 and 2001.................... 3
Notes to Consolidated Financial Statements.................. 4
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations....................................... 11
Liquidity and Capital Resources............................. 15
Item 3. Quantitative and Qualitative Disclosures About Market Risk.. 21
Item 4. Controls and Procedures..................................... 22
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K............................ 23
SIGNATURES AND CERTIFICATIONS......................................... 24
i
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In Thousands)
September 30, December 31,
2002 2001
--------------- ---------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,438 $ 4,546
Restricted funds 26,357 7,699
Accounts receivable, net of allowance of $0 and $32, respectively 18,036 17,789
Due from affiliates 195 1,127
Fuel inventory and supplies 6,567 10,228
Other current assets 982 511
Asset for derivative contracts --- 446
--------------- ---------------
Total current assets 53,575 42,346
--------------- ---------------
PLANT AND EQUIPMENT:
Plant and equipment, at cost 374,931 373,476
Less: Accumulated depreciation 108,798 99,563
--------------- ---------------
Plant and equipment, net 266,133 273,913
--------------- ---------------
LONG-TERM RESTRICTED FUNDS 30,595 24,314
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $9,712 and $8,901, respectively 6,579 7,390
--------------- ---------------
TOTAL ASSETS $ 356,882 $ 347,963
=============== ===============
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ 214 $ 1,729
Accrued bond interest payable 8,239 357
Accrued fuel expenses 9,562 8,689
Accrued property taxes 3,244 2,296
Accrued operating and maintenance expenses 1,294 1,262
Other accrued expenses 3,793 4,173
Due to affiliates 369 2,008
Current portion of long-term bonds 15,406 13,529
Current portion of liability for derivative contracts 2,858 3,688
--------------- ---------------
Total current liabilities 44,979 37,731
LONG-TERM LIABILITIES:
Deferred revenue 4,067 4,597
Other long-term liabilities 7,611 7,070
Long-term bonds - net of current portion 340,737 349,235
Liability for derivative contracts - net of current
portion 3,205 5,113
--------------- ---------------
Total liabilities 400,599 403,746
--------------- ---------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (369) (458)
Limited partners' deficits (37,285) (46,524)
Accumulated other comprehensive loss (6,063) (8,801)
--------------- ---------------
Total partners' deficits (43,717) (55,783)
--------------- ---------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 356,882 $ 347,963
=============== ===============
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
1
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands)
For the Three Months Ended For the Nine Months Ended
--------------------------------- ---------------------------------
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
---------------- --------------- ---------------- ---------------
OPERATING REVENUES:
Electric and steam $ 53,442 $ 52,433 $ 147,836 $ 159,944
Fuel revenues 4,834 691 16,819 17,330
---------------- ---------------
---------------- ---------------
Total operating revenues 58,276 53,124 164,655 177,274
---------------- --------------- ---------------- ---------------
COST OF REVENUES:
Fuel and transmission costs 31,078 26,541 83,017 99,396
Unrealized loss on derivative contracts --- --- 446 ---
Other operating and maintenance 2,996 3,727 20,297 14,264
Depreciation 3,140 3,125 9,400 9,363
---------------- --------------- ---------------- ---------------
Total cost of revenues 37,214 33,393 113,160 123,023
---------------- --------------- ---------------- ---------------
GROSS PROFIT 21,062 19,731 51,495 54,251
---------------- --------------- ---------------- ---------------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 425 478 1,126 1,448
Other general and administrative 811 609 2,272 1,891
Amortization of deferred financing charges 267 276 811 836
---------------- --------------- ---------------- ---------------
Total other operating expenses 1,503 1,363 4,209 4,175
---------------- --------------- ---------------- ---------------
OPERATING INCOME 19,559 18,368 47,286 50,076
---------------- --------------- ---------------- ---------------
INTEREST (INCOME) EXPENSE:
Interest income (195) (377) (662) (1,682)
Interest expense 7,889 8,141 23,947 24,678
---------------- --------------- ---------------- ---------------
Total interest expense, net 7,694 7,764 23,285 22,996
---------------- --------------- ---------------- ---------------
Income before cumulative effect of a change
in accounting principle 11,865 10,604 24,001 27,080
Cumulative effect of a change in
accounting principle --- (519) --- (519)
---------------- --------------- ---------------- ---------------
NET INCOME $ 11,865 $ 10,085 $ 24,001 $ 26,561
================ =============== ================ ===============
NET INCOME ALLOCATION:
General partners $ 118 $ 101 $ 240 $ 266
Limited partners 11,747 9,984 23,761 26,295
--------------- ---------------- --------------- ----------------
TOTAL $ 11,865 $ 10,085 $ 24,001 $ 25,561
================ =============== ================ ===============
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
For the Three Months Ended For the Nine Months Ended
----------------------------- -------------------------------
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
-------------- -------------- --------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 11,865 $ 10,085 $ 24,001 $ 26,561
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting 519
principle --- 519 ---
Depreciation and amortization 3,407 3,401 10,211 10,199
Unrealized loss on derivative contracts --- --- 446 ---
Deferred revenue (176) (176) (530) (530)
Loss on disposal of plant and equipment --- 59 481 91
Increase (decrease) in cash resulting from a
change in:
Restricted funds 1,652 558 (1,750) 1,450
Accounts receivable 106 509 (247) 2,467
Due from affiliates 801 528 932 3,763
Fuel inventory and supplies (646) (1,194) 3,661 (3,227)
Other current assets 316 330 (471) (490)
Accounts payable (154) 870 (1,515) 821
Accrued bond interest payable 7,888 8,141 7,882 8,135
Accrued fuel expenses (105) (1,298) 873 (5,965)
Accrued property taxes 44 --- 948 100
Accrued operating and maintenance expenses (2,280) (154) 32 (430)
Other accrued expenses 310 556 (380) 1,826
Due to affiliates (740) (1,331) (1,639) 342
Other long-term liabilities 730 730 541 641
-------------- -------------- --------------- ---------------
Net cash provided by operating activities 23,018 22,133 43,476 46,273
-------------- -------------- --------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions 14 (3) (2,101) (919)
Proceeds from disposal of plant and equipment --- --- --- 10
-------------- -------------- --------------- ---------------
Net cash provided by (used in) investing 14 (3) (2,101) (909)
activities -------------- -------------- --------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds (23,188) (21,670) (23,189) (21,670)
Distributions to partners --- (1,314) (14,673) (18,859)
Repayment of long-term debt --- --- (6,621) (6,010)
-------------- -------------- --------------- ---------------
Net cash used in financing activities (23,188) (22,984) (44,483) (46,539)
-------------- -------------- --------------- ---------------
NET DECREASE IN CASH AND CASH EQUIVALENTS (156) (854) (3,108) (1,175)
-------------- -------------- --------------- ---------------
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 1,594 2,866 4,546 3,187
-------------- -------------- --------------- ---------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 1,438 $ 2,012 $ 1,438 $ 2,012
============== ============== =============== ===============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ --- $ --- $ 16,064 $ 16,543
============== ============== =============== ===============
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
3
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. Basis of Presentation
The accompanying unaudited consolidated financial statements include Selkirk
Cogen Partners, L.P. and its wholly-owned subsidiary, Selkirk Cogen Funding
Corporation (collectively the “Partnership”). All significant
intercompany accounts and transactions have been eliminated.
The consolidated financial statements for the interim periods presented are
unaudited and have been prepared pursuant to the rules and regulations of the
Securities and Exchange Commission. Certain information and footnote disclosures
normally included in financial statements prepared in accordance with accounting
principles generally accepted in the United States have been omitted pursuant to
rules and regulations applicable to interim financial statements. The
information furnished in the consolidated financial statements reflects all
normal recurring adjustments, which, in the opinion of management, are necessary
for a fair presentation of such financial statements. Certain reclassifications
have been made to the Consolidated Statement of Operations for the three and
nine months ended September 30, 2001 to conform with the current period’s
basis of presentation. Operating results for the three and nine months ended
September 30, 2002 are not necessarily indicative of the results that may be
expected for the year ended December 31, 2002.
These consolidated financial statements should be read in conjunction with the
audited consolidated financial statements included in the Partnership’s
December 31, 2001 Annual Report on Form 10-K.
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions. These estimates and assumptions affect the reported
amounts of revenue, expenses, assets and liabilities, and the disclosure of
contingencies. Actual results could differ from these estimates.
Comprehensive Income
The Partnership’s comprehensive income consists principally of net income
and changes in the market value of certain financial hedges under Statement of
Financial Accounting Standards (“SFAS”) No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137
and 138, “Accounting for Certain Derivative Instruments and Certain Hedging
Activities” (collectively, SFAS No. 133).
4
The schedule below summarizes the activities affecting comprehensive income for the three and nine months ended September 30, 2002 and 2001 (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Net income $ 11.9 $ 10.1 $ 24.0 $ 26.6
Cumulative effect of adoption of
SFAS No. 133 --- --- --- (9.0)
Net gain (loss) from current period
hedging transactions in accordance
with SFAS No. 133 (1.2) (1.3) 0.2 (2.4)
Net reclassification to earnings 0.8 0.8 2.5 2.3
------------- ------------- ------------- -------------
Comprehensive income $ 11.5 $ 9.6 $ 26.7 $ 17.5
============= ============= ============= =============
Note 2. Significant Accounting Policies
Except as disclosed, the Partnership is following the same accounting principles
discussed in the Partnership’s December 31, 2001 Annual Report on Form
10-K.
Adoption of New Accounting Pronouncements
On April 1, 2002, the Partnership implemented two interpretations issued by the
Financial Accounting Standard Board’s (“FASB”) Derivatives
Implementation Group (“DIG”). DIG Issues C15 and C16 changed the
definition of normal purchases and sales included in SFAS No. 133. Previously,
certain derivative commodity contracts for the physical delivery of purchase and
sale quantities transacted in the normal course of business were exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exemption, and
thus were not marked-to-market and reflected on the balance sheet like other
derivatives. Instead, these contracts were recorded on an accrual basis.
DIG Issue C15 changed the definition of normal purchases and sales for certain
power contracts. The Partnership determined that all of its power contracts
continue to qualify for the normal purchases and sales exemption. DIG Issue C16
disallowed normal purchases and sales treatment for commodity contracts (other
than power contracts) that contain volumetric variability or optionality. The
Partnership determined that one of its long-term fuel contracts failed to
continue qualifying for the normal purchase exemption under the requirements of
DIG Issue C16. However, because the long term fuel contract has market
based pricing, the Partnership currently estimates its fair value to always be
zero, resulting in no impact to the Partnership’s consolidated financial
statements.
5
In June 2001, the FASB issued SFAS No. 141, entitled, Business Combinations.
This statement prohibits the use of the pooling-of-interests method of
accounting for business combinations initiated after June 30, 2001 and applies
to all business combinations accounted for under the purchase method that are
completed after June 30, 2001. This statement was adopted on January 1, 2002,
and did not have an impact on the Partnership’s consolidated financial
statements.
Also in June 2001, the FASB issued SFAS No. 142, entitled, Goodwill and Other
Intangible Assets. This statement eliminates the amortization of goodwill, and
requires goodwill to be reviewed periodically for impairment. This statement
also requires the useful lives of previously recognized intangible assets to be
reassessed and the remaining amortization periods to be adjusted accordingly.
This statement is effective for fiscal years beginning after December 15, 2001,
for all goodwill and other intangible assets recognized on the
Partnership’s consolidated balance sheets at that date, regardless of when
the assets were initially recognized. This statement was adopted on January 1,
2002, and did not have an impact on the Partnership’s consolidated
financial statements.
In August 2001, the FASB issued SFAS No. 144, entitled, Accounting for the
Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supercedes SFAS No.
121, entitled, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of, but retains its fundamental provisions for
recognizing and measuring impairment of long-lived assets to be held and used.
This statement also requires that all long-lived assets to be disposed of by
sale are carried at the lower of carrying amount or fair value less cost to
sell, and that depreciation should cease to be recorded on such assets. SFAS No.
144 standardizes the accounting and presentation requirements for all long-lived
assets to be disposed of by sale, superceding previous guidance for discontinued
operations of business segments. This statement is effective for fiscal years
beginning after December 15, 2001. This statement was adopted on January 1,
2002, and did not have an impact on the Partnership’s consolidated
financial statements.
Related Party Transactions
JMCS I Management, Inc. (“JMCS I Management”) manages the day-to-day
operation of the Partnership and is compensated at agreed-upon billing rates
that are adjusted quadrennially in accordance with an administrative services
agreement. All officers and directors of JMC Selkirk, Inc., are also officers
and directors of JMCS I Management. For the nine months ended September 30, 2002
and 2001, expenses incurred for services provided by JMCS I Management totaled
approximately $1.1 million and $1.5 million, respectively. The cost of services
provided by JMCS I Management was included in administrative services –
affiliates in the accompanying consolidated statements of operations. The total
amount due to JMCS I Management for these services at September 30, 2002, was
approximately $0.4 million.
6
The Partnership purchases from and sells gas to PG&E Energy Trading –
Gas Corporation (“PG&E Energy Trading – Gas”), PG&E
Energy Trading - Canada Corporation (“PG&E Energy Trading –
Canada”), Pittsfield Generating Company, L.P. (“Pittsfield
Generating”) and MASSPOWER, affiliates of JMC Selkirk, Inc., at fair value.
Gas purchased from PG&E Energy Trading – Gas, Pittsfield and MASSPOWER
for the nine months ended September 30, 2002 totaled approximately $7,884.8
thousand, $3.7 thousand and $41.9 thousand, respectively. Gas purchased from
PG&E Energy Trading – Gas, Pittsfield and MASSPOWER for the nine months
ended September 30, 2001 totaled approximately $2,677.8 thousand, $35.8 thousand
and $2,535.5 thousand, respectively. Gas sold to PG&E Energy Trading –
Gas, PG&E Energy Trading – Canada, Pittsfield and MASSPOWER for the
nine months ended September 30, 2002 totaled approximately $16,223.7 thousand,
$204.6 thousand, $0.5 thousand and $58.7 thousand, respectively. Gas sold to
PG&E Energy Trading – Gas and Pittsfield for the nine months ended
September 30, 2001 totaled approximately $15,209.5 thousand and $79.8 thousand,
respectively. Gas purchases were recorded as fuel costs and sales of gas were
recorded as fuel revenues in the accompanying consolidated statements of
operations. The total amount due to PG&E Energy Trading – Gas for
purchases of gas at September 30, 2002 was approximately $15.5 thousand and the
total amount due from PG&E Energy Trading – Gas for sales of gas at
September 30, 2002 was approximately $140.2 thousand.
In May 1996, the Partnership entered into an enabling agreement with PG&E
Energy Trading – Power, L.P. ("PG&E Energy Trading-Power"), an
affiliate of JMC Selkirk, Inc., to purchase and sell electric capacity, electric
energy, and other electric-related products. For the nine months ended September
30, 2002 and 2001, sales to PG&E Energy Trading – Power totaled
approximately $1.6 million and $3.8 million, respectively. Sales to PG&E
Energy Trading – Power were recorded as electric revenues in the
accompanying consolidated statements of operations. The total amount due from
PG&E Energy Trading – Power at September 30, 2002 for sales of electric
capacity was approximately $0.1 million.
The Partnership has two agreements with Iroquois Gas Transmission System
(“IGTS”), an indirect affiliate of JMC Selkirk, Inc., to provide firm
transportation of natural gas from Canada. For the nine months ended September
30, 2002, firm fuel transportation services from IGTS totaled approximately $5.6
million and $5.8 million, respectively. These services were recorded as fuel
costs in the accompanying consolidated statements of operations. The total
amount due IGTS for firm transportation at September 30, 2002, was approximately
$0.6 million.
Note 3. Accounting For Derivative Contracts
The Partnership has two foreign currency exchange contracts to hedge against
fluctuations in fuel transportation costs, which are denominated in Canadian
dollars. For the three months ended September 30, 2002 and 2001, amounts charged
to fuel costs as a result of losses realized from these contracts totaled
approximately $0.8 million for each of the periods. For the nine months ended
September 30, 2002 and 2001, amounts charged to fuel costs as a result of losses
realized from these contracts totaled approximately $2.5 million and $2.3
million, respectively. The Partnership expects that net derivative losses of
approximately $2.9 million, included in accumulated other comprehensive loss as
of September 30, 2002, will be reclassified into earnings within the next twelve
months. The actual amounts reclassified from accumulated other comprehensive
loss to earnings will differ as a result of changes in exchange rates.
7
The schedule below summarizes the activities affecting accumulated other
comprehensive loss from derivative contracts for the three months and nine
months ended September 30, 2002 and 2001 (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Beginning accumulated other
comprehensive loss at July 1 and
January 1, respectively $ (5.7) $ (8.6) $ (8.8) $ (9.0)
Net gain (loss) from current
period hedging transactions (1.2) (1.3) 0.2 (2.4)
Net reclassification to earnings 0.8 0.8 2.5 2.3
------------- ------------- ------------- -------------
Ending accumulated other comprehensive loss $ (6.1) $ (9.1) $ (6.1) $ (9.1)
============= ============= ============= =============
The Partnership enters into peak shaving arrangements whereby it grants to local
distribution companies or other purchasers a call on a specified portion of the
Partnership’s firm natural gas supply for a specified number of days during
the winter season. Revenues from peak shaving arrangements for the nine months
ended September 30, 2002 and 2001 were approximately $0.5 million for each of
the periods. On July 1, 2001, the Partnership determined peak shaving
arrangements were no longer exempt from the requirements of SFAS No. 133 and
recorded a loss of approximately $0.5 million reflecting the cumulative effect
of a change in accounting principle. Changes in the fair value of peak shaving
arrangements are recorded on the consolidated statements of operations as an
unrealized gain or loss on derivative contracts. Unrealized loss on derivative
contracts for the nine months ended September 30, 2002 and 2001 was
approximately $0.4 million and $0, respectively.
Note 4. Concentrations of Credit Risk
Credit risk is the risk of loss the Partnership would incur if counterparties
were to fail to perform their contractual obligations (accounts receivable). The
Partnership primarily conducts business with customers in the energy industry,
such as investor-owned utilities, energy trading companies, financial
institutions, gas production companies and gas transportation companies located
in the United States and Canada. This concentration of counterparties may impact
the Partnership’s overall exposure to credit risk in that its
counterparties may be similarly affected by changes in economic, regulatory or
other conditions. The Partnership mitigates potential credit losses in
accordance with established credit approval practices and limits by dealing
primarily with counterparties it considers to be of investment grade.
8
As of September 30, 2002, the Partnership’s credit risk is primarily
concentrated with the following customers: Consolidated Edison Company of New
York, Inc., Niagara Mohawk Power Corporation and the New York Independent System
Operator, all of whom are considered to be of investment grade. During the three
months ended September 30, 2002, the parent company of three of the
Partnership’s customers, all of whom are related parties, PG&E Energy
Trading – Gas, PG&E Energy Trading – Canada and PG&E Energy
Trading – Power was downgraded below investment grade. The
Partnership’s net credit exposure to PG&E Energy Trading – Gas and
PG&E Energy Trading – Power at September 30, 2002 was approximately
$0.1 million and $0.1 million, respectively.
Note 5. Relationship with Affiliated Companies
Bankruptcy of Pacific Gas and Electric Company
JMC Selkirk, Inc. is the managing general partner of the Partnership.
Approximately 90% of the ownership interest in JMC Selkirk, Inc. is held by an
indirect subsidiary of PG&E National Energy Group, Inc. ("NEG"). NEG is an
indirect, wholly-owned subsidiary of PG&E Corporation, the parent company of
Pacific Gas and Electric Company (the "Utility").
In December 2000, and in January and February 2001, PG&E Corporation and NEG
completed a corporate restructuring of NEG that involved the use or creation of
limited liability companies (“LLCs”) as intermediate owners between a
parent company and its subsidiaries. One of these LLCs is PG&E National
Energy Group, LLC, which owns 100% of the stock of NEG. After the restructuring
was completed, two independent rating agencies, Standard and Poor’s
(“S&P”) and Moody’s Investor Services
(“Moody’s”) issued investment grade ratings for NEG and
reaffirmed such ratings for certain NEG subsidiaries. On April 6, 2001, the
Utility filed a voluntary petition for relief under the provisions of Chapter 11
of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the United States
Bankruptcy Court for the Northern District of California (“Bankruptcy
Court”). Pursuant to the Bankruptcy Code, the Utility retains control of
its assets and is authorized to operate its business as a debtor-in-possession
while being subject to the jurisdiction of the Bankruptcy Court. The Utility and
PG&E Corporation have jointly filed a plan of reorganization with the
Bankruptcy Court that entails separating the Utility into four distinct
businesses. The proposed plan of reorganization does not directly affect NEG or
any of its subsidiaries. The Managing General Partner believes that NEG and its
direct and indirect subsidiaries, including JMC Selkirk, Inc., Pentagen
Investors, L.P. and the Partnership, would not be substantively consolidated
with PG&E Corporation in any insolvency or bankruptcy proceeding involving
PG&E Corporation or the Utility.
9
NEG Rating Actions
Currently, NEG is experiencing liquidity problems due to the deterioration in
PG&E Corporation’s credit position, the Utility’s bankruptcy and
the downturn in the energy industry. On July 31, 2002 and August 5, 2002,
S&P and Moody’s, respectively, downgraded NEG’s ratings, as
previously reported. On October 8, 2002, October 16, 2002 and October 18, 2002,
Moody’s further downgraded the senior unsecured debt rating, issuer rating
and syndicated bank credit facilities of NEG. Moody’s current rating of NEG
is “B3". On October 11, 2002, S&P further downgraded certain of
NEG’s debt facilities. S&P’s current rating of NEG is
“B-". The result of these downgrades has left the credit ratings of
NEG and its debt instruments below investment grade. Both S&P and
Moody’s credit ratings assigned to NEG and its affiliates are under review
for possible further downgrade. The credit rating agency action has had no
material impact on the financial condition or results of operations of the
Partnership.
On October 8, 2002, Moody’s stated that in conjunction with the downgrade
of NEG it had placed the Partnership’s debt under review for possible
downgrade. On October 15, 2002, S&P stated that the recent downgrade of NEG
will not have an affect on the rating of the Partnership’s debt at this
time. S&P’s rating of the Partnership’s debt is “BBB-".
On November 5, 2002, Moody’s issued an opinion update changing the rating
outlook of the Partnership’s debt to “under review for possible
downgrade” from “stable” for the Partnership’s debt due in
2007 and “negative outlook” for the Partnership’s debt due in
2012. Moody’s rating of the Partnership’s debt is “Baa3".
Note 6. Title V Permit
On November 6, 2001, the Partnership received from the New York State Department
of Environmental Conservation (the “DEC”) the Facility’s Title V
operating permit endorsed by the DEC on November 2, 2001 (the “Title V
Permit”). The Title V Permit as received by the Partnership contains
conditions that conflict with the Partnership’s existing air permits, and
the Facility’s compliance with these conditions under certain operating
circumstances would be problematic. Further, the Partnership believes that
certain of the conditions contained in the Title V Permit are inconsistent with
the laws and regulations underlying the Title V program and Title V operating
permits issued by the DEC to comparable electric generating facilities in New
York. By letter dated November 12, 2001, the Partnership has filed with the DEC
a request for an adjudicatory hearing to address and resolve the issues
presented by the Title V Permit. The DEC has confirmed that the terms and
conditions of the Title V Permit are stayed pending a final DEC decision on the
appeal. Since November 12, 2001, the Partnership and DEC staff have engaged in
negotiations regarding the Title V Permit. At this time, the Partnership cannot
assess whether a settlement can be achieved, the likely outcome of the
adjudicatory hearing if no settlement is achieved, or the impact on the
Facility.
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Cautionary Statement Regarding Forward-Looking Statements
Certain statements included herein are forward-looking statements concerning the
Partnership’s operations, economic performance and financial condition.
Such statements are subject to various risks and uncertainties. Actual results
could differ materially from those currently anticipated due to a number of
factors, including general business and economic conditions; the performance of
equipment; levels of dispatch; the receipt of certain capacity and other fixed
payments; electricity prices; natural gas resale prices; fuel deliveries and
prices; the consequences, if any, of a potential downgrade of the credit ratings
for the Partnership’s debt, and the renewal of the Partnership’s
credit agreement, both as described in “Liquidity and Capital
Resources” below; the outcome of the negotiations with the New York State
Department of Environmental Conservation regarding the Facility’s Title V
operating permit as described in “Regulations and Environmental
Matters” below; and whether Consolidated Edison Company of New York, Inc.
(“Con Edison”) were to prevail in its claim to Unit 2’s excess
natural gas volumes as described in the Partnership's December 31, 2001 Annual
Report on Form 10-K.
Results of Operations
Three and Nine Months Ended September 30, 2002 Compared to the Three and
Nine Months Ended September 30, 2001
The Partnership earned net income of approximately $11.9 million for the three
months ended September 30, 2002 as compared to approximately $10.1 million for
the corresponding period in the prior year. The Partnership earned net income of
approximately $24.0 million for the nine months ended September 30, 2002 as
compared to approximately $26.6 million for the corresponding period in the
prior year. The $1.8 million increase in net income for the three months ended
September 30, 2002 was primarily due to higher operating revenues, lower
maintenance expenses and the Partnership recording a loss in the prior year of
approximately $0.5 million reflecting the cumulative effect of a change in
accounting principle. The $2.6 million decrease in net income for the nine
months ended September 30, 2002 was primarily due to higher maintenance expenses
resulting from differences in the scheduling and scope of planned maintenance,
partially offset by lower fuel costs.
Effective July 1, 2001, the Partnership determined that certain gas contracts no
longer meet the definition of normal purchases and sales and are no longer
exempt from the requirements of Statement of Financial Accounting Standards
(“SFAS”) No. 133, “Accounting for Derivative Instruments and
Hedging Activities,” as amended by SFAS Nos. 137 and 138, “Accounting
for Certain Derivative Instruments and Certain Hedging Activities”
(collectively, SFAS No. 133). The cumulative effect of a change in accounting
principle was a loss of approximately $0.5 million. Future changes in the fair
value of the contracts will be recorded on the income statement as an unrealized
gain or loss on derivative contracts.
11
Total operating revenues for the three and nine months ended September 30, 2002
were approximately $58.3 million and $164.7 million as compared to approximately
$53.1 million and $177.3 million for the corresponding periods in the prior
year.
Electric Revenues (dollars and kWh's in millions):
- --------------------------------------------------
For the Three Months Ended
September 30, 2002 September 30, 2001
- ------------------------------------------------------------ -------------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 15.3 153.6 87.0% 100.0% 16.0 158.4 89.8% 99.9%
Unit 2 38.1 575.4 98.4% 100.0% 36.8 573.1 97.8% 100.0%
For the Nine Months Ended
September 30, 2002 September 30, 2001
- ------------------------------------------------------------ -------------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 42.9 491.9 94.1% 98.4% 44.3 346.2 66.2% 70.8%
Unit 2 104.8 1,353.3 78.0% 85.2% 115.6 1,483.0 85.4% 89.5%
Unit 1 Electric Revenues (dollars in millions):
- -----------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Niagara Mohawk $ 8.3 $ 8.9 $ 24.7 $ 27.8
ISO 6.8 6.8 17.9 12.7
PG&E Energy Trading - Power 0.2 0.3 0.3 3.8
------------- ------------- ------------- -------------
$ 15.3 $ 16.0 $ 42.9 $ 44.3
============= ============= ============= =============
The $0.7 million decrease in Unit 1 electric revenues for the three months ended
September 30, 2002 was primarily due to lower volumes of delivered energy and
lower fuel index pricing in the energy component of the Niagara Mohawk Power
Corporation (“Niagara Mohawk”) monthly contract payment. The $1.4
million decrease in Unit 1 electric revenues for the nine months ended September
30, 2002 was primarily due to lower fuel index pricing in the energy component
of the Niagara Mohawk monthly contract payment and lower market energy prices,
partially offset by higher volumes of delivered energy. The lower volume of
delivered energy for the nine months ended September 30, 2001 resulted from a
seven week scheduled maintenance outage in April and May 2001. Energy and
capacity sales to the New York Independent System Operator (“ISO”)
were sold at ISO market clearing prices, and energy and capacity sales to
PG&E Energy Trading – Power, L.P., an affiliate of JMC Selkirk, Inc.
(“PG&E Energy Trading - Power”), were sold at negotiated market
prices.
12
Unit 2 Electric Revenues (dollars in millions):
- -----------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Con Edison $ 38.3 $ 36.8 $ 103.6 $ 114.5
ISO (0.2) --- (0.1) 0.7
PG&E Energy Trading - Power --- --- 1.3 ---
Unrelated third party --- --- --- 0.4
------------- ------------- ------------- -------------
$ 38.1 $ 36.8 $ 104.8 $ 115.6
============= ============= ============= =============
The $1.3 million increase in Unit 2 electric revenues for the three months ended
September 30, 2002 was primarily due to escalation in the Con Edison contract
capacity payment and higher fuel index pricing in the Con Edison contract price
for delivered energy. The $10.8 million decrease in Unit 2 electric revenues for
the nine months ended September 30, 2002 was primarily due to lower fuel index
pricing in the Con Edison contract price for delivered energy and lower volumes
of delivered energy resulting from a four week scheduled maintenance outage in
January 2002 and a six week scheduled maintenance outage in April and May 2002.
Steam revenues for the three and nine months ended September 30, 2002 of
approximately $0.3 million and $0.5 million were reduced by a reserve of
approximately $0.3 million and $0.4 million, respectively. Steam revenues for
the three and nine months ended September 30, 2001 of approximately $0.1 million
and $0.7 million were reduced by a reserve of approximately $0.5 million and
$0.7 million, respectively. The Partnership charges General Electric a nominal
price for steam delivered in an amount up to the annual equivalent of 160,000
lbs/hr (the “Discounted Quantity”). The increase in steam revenues for
the three and nine months ended September 30, 2002 was primarily due to an
increase in steam sales in excess of the Discounted Quantity to General
Electric. Delivered steam for the three months ended September 30, 2002 was
approximately 383.3 million pounds or 175,524 lbs/hr as compared to
approximately 292.6 million pounds or 133,994 lbs/hr for the corresponding
period in the prior year. Delivered steam for the nine months ended September
30, 2002 was approximately 1,052.5 million pounds or 161,235 lbs/hr as compared
to approximately 1,053.7 million pounds or 160,818 lbs/hr for the corresponding
period in the prior year.
13
Fuel Revenues (dollars and MMBtu's in millions):
- ------------------------------------------------
For the Three Months Ended
September 30, 2002 September 30, 2001
--------------------------------- -------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Gas Resales 0.4 0.1 0.4 0.1
Fuel Optimizations 4.4 1.4 0.3 0.1
--------------- ------------- ------------- --------------
4.8 1.5 0.7 0.2
=============== ============= ============= ==============
For the Nine Months Ended
September 30, 2002 September 30, 2001
--------------------------------- -------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Gas Resales 9.1 2.7 15.2 2.7
Fuel Optimizations 7.2 2.3 1.6 0.3
Peak Shaving Arrangements 0.5 --- 0.5 ---
--------------- ------------- ------------- --------------
16.8 5.0 17.3 3.0
=============== ============= ============= ==============
The $4.1 million increase in fuel revenues for the three months ended September
30, 2002 was primarily due to higher volumes of natural gas sold under fuel
optimizations. The $0.5 million decrease in fuel revenues for the nine months
ended September 30, 2002 was primarily due to lower market natural gas prices,
partially offset by higher volumes of natural gas sold under fuel optimizations.
Fuel and Transmission Costs (dollars and MMBtu's in millions):
- --------------------------------------------------------------
For the Three Months Ended
September 30, 2002 September 30, 2001
---------------------------------- ------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Fuel Supply and
Transportation* 24.4 7.1 23.7 7.1
Fuel Optimizations 4.2 1.4 0.4 0.1
Transmission Costs 2.5 --- 2.4 ---
--------------- -------------- ------------ --------------
31.1 8.5 26.5 7.2
=============== ============== ============ ==============
For the Nine Months Ended
September 30, 2002 September 30, 2001
---------------------------------- ------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Fuel Supply and
Transportation* 69.8 20.7 91.2 20.9
Fuel Optimizations 6.9 2.3 1.7 0.3
Transmission Costs 6.3 --- 6.5 ---
--------------- -------------- ------------ --------------
83.0 23.0 99.4 21.2
=============== ============== ============ ==============
* Includes the cost of fuel associated with the production of electricity and gas resales.
14
The $4.6 million increase in fuel and transmission costs for the three months
ended September 30, 2002 was primarily due to higher volumes of natural gas
purchased under fuel optimizations. The $16.4 million decrease in fuel and
transmission costs for the nine months ended September 30, 2002 was primarily
due to the lower price of natural gas under the firm fuel supply contracts,
partially offset by higher volumes of natural gas purchased under fuel
optimizations. The Partnership has foreign currency swap agreements to hedge
against future exchange rate fluctuations under fuel transportation agreements,
which are denominated in Canadian dollars. As a result of the currency swap
agreements, fuel costs for the three and nine months ended September 30, 2002
were increased by approximately $0.8 million and $2.5 million as compared to
approximately $0.8 million and $2.3 million for the corresponding periods in the
prior year.
Unrealized loss on derivative contracts for the three and nine months ended
September 30, 2002 was approximately $0 and $0.4 million as compared to $0 for
the corresponding periods in the prior year. The unrealized loss reflects the
change in fair value of peak shaving arrangements recorded in the first quarter
of 2002.
Other operating and maintenance expenses for the three and nine months ended
September 30, 2002 were approximately $3.0 million and $20.3 million as compared
to approximately $3.7 million and $14.3 million for the corresponding periods in
the prior year. The $6.0 million increase for the nine months ended September
30, 2002 in other operating and maintenance expenses were primarily due to
differences in the scheduling and scope of planned maintenance. The first and
second quarters of 2002 each included a scheduled maintenance outage on Unit 2,
whereas the second quarter of 2001 included a scheduled maintenance outage on
Unit 1.
Liquidity and Capital Resources
Net cash provided by operating activities for the three and nine months ended
September 30, 2002 was approximately $23.0 million and $43.5 million as compared
to approximately $22.1 million and $46.3 million for the corresponding periods
in the prior year. Net cash provided by operating activities primarily
represents net income, adjusted by non-cash expenses and income, plus the net
effect of changes within the Partnership's operating assets and liability
accounts.
Net cash provided by (used in) investing activities for the three and nine
months ended September 30, 2002 was approximately $14.0 thousand and $(2.1)
million as compared to approximately $(3.0) thousand and $(909.0) thousand for
the corresponding periods in the prior year. Net cash provided by (used in)
investing activities primarily represents additions to plant and equipment.
15
Net cash used in financing activities for the three and nine months ended
September 30, 2002 was approximately $23.2 million and $44.5 million as compared
to approximately $23.0 million and $46.5 million for the corresponding periods
in the prior year. Pursuant to the Partnership's Depositary and Disbursement
Agreement, administered by Bankers Trust Company, as depositary agent, the
Partnership is required to maintain certain restricted funds. Net cash flows
used in financing activities during the three months ended September 30, 2002
and 2001 primarily represent deposits of monies into the Interest, Principal and
Debt Service Reserve Funds. Net cash flows used in financing activities during
the nine months ended September 30, 2002 and 2001 primarily represent deposits
of monies into the Interest, Principal and Debt Service Reserve Funds,
distributions to partners and the semi-annual payment of principal and interest
on long-term debt.
On October 8, 2002, Moody's Investors Services ("Moody's") stated that in
conjunction with the downgrade of PG&E National Energy Group, Inc. ("NEG"),
it had placed the Partnership's debt under review for possible downgrade. On
October 15, 2002, Standard and Poor's ("S&P") stated that the recent
downgrade of NEG will not have an affect on the rating of the Partnership's debt
at this time. S&P's rating of the Partnership's debt is "BBB-". On November
5, 2002, Moody's issued an opinion update changing the rating outlook of the
Partnership's debt to "under review for possible downgrade" from "stable" for
the Partnership's debt due in 2007 and "negative outlook" for the Partnership's
debt due in 2012. Moody's rating of the Partnership's debt is "Baa3". The
Partnership is currently undertaking a review of its significant contractual
obligations in order to assess the consequences, if any, of a potential
downgrade of the credit ratings for the Partnership's debt.
The Partnership has available for its use a credit agreement, as amended
("Credit Agreement"), with a maximum available credit of approximately $7.5
million through August 8, 2003. Outstanding balances bear interest at prime rate
plus .375% per annum with principal and interest payable monthly in arrears. The
Credit Agreement is available to the Partnership for the purposes of meeting
letters of credit requirements under various project contracts and for meeting
working capital requirements. The maximum amount available under the Credit
Agreement for working capital purposes is $5.0 million. As of September 30,
2002, there were no amounts drawn or balances outstanding under either the
letters of credit or the working capital arrangement.
Future operating results and cash flows from operations are dependent on, among
other things, the performance of equipment; levels of dispatch; the receipt of
certain capacity and other fixed payments; electricity prices; natural gas
resale prices; fuel deliveries and prices; the consequences, if any, of a
potential downgrade of the credit ratings for the Partnership's debt; and the
renewal of the Partnership's credit agreement. A significant change in any of
these factors could have a material adverse effect on the results of operations
for the Partnership.
The Partnership believes, based on current conditions and circumstances, it will
have sufficient cash flows from operations to fund existing debt obligations and
operating costs during 2002.
16
Market Risk
Interest Rates
Interest rate risk is the risk that changes in the interest rates could
adversely affect earnings and cash flow. The Partnership’s cash and
restricted cash are sensitive to changes in interest rates. Interest rate
changes would result in a change in interest income due to the difference
between the current interest rates on cash and restricted cash and the variable
rate that these financial instruments may adjust to in the future. Interest rate
risk sensitivity analysis is used to measure interest rate risk by computing
estimated changes in cash flows as a result of assumed changes in market
interest rates. As of September 30, 2002, if interest rates change by 10
percent, the change would be immaterial to the Partnership’s consolidated
financial statements.
The Partnership’s long-term bonds have fixed interest rates. Changes in the
current market rates for the bonds would not result in a change in interest
expense due to the fixed coupon rate of the bonds.
Foreign Currency Exchange Rates
Foreign currency risk is the risk of changes in value of pending financial
obligations in foreign currencies that could occur prior to the settlement of
the obligation due to a change in the value of that foreign currency in relation
to the U.S. dollar. The Partnership uses currency swap agreements to partially
hedge foreign currency exposure under fuel transportation agreements that are
denominated in Canadian dollars. In the event a counterparty fails to meet the
terms of the currency swap agreements, the Partnership would be exposed to the
risk that fluctuating currency exchange rates may adversely impact its financial
results.
The Partnership uses sensitivity analysis to measure its foreign currency
exchange rate exposure not covered by the currency swap agreements. Based upon a
sensitivity analysis at September 30, 2002, a 10 percent devaluation of the
Canadian dollar would be immaterial to the Partnership’s consolidated
financial statements.
Energy Commodity Prices
The Partnership seeks to reduce its exposure to market risk associated with
energy commodities such as electric power and natural gas through the use of
long-term purchase and sale contracts. As part of its fuel management
activities, the Partnership also enters into agreements to resell its long-term
natural gas volumes, when it is feasible to do so, at favorable prices relative
to the cost of contract volumes and the cost of substitute fuels. To the extent
the Partnership has open positions, it is exposed to the risk that fluctuating
market prices may adversely impact its financial results.
17
Credit Risk
Credit risk is the risk of loss the Partnership would incur if counterparties
were to fail to perform their contractual obligations. The Partnership primarily
conducts business with customers in the energy industry, such as investor-owned
utilities, energy trading companies, financial institutions, gas production
companies and gas transportation companies located in the United States and
Canada. This concentration of counterparties may impact the Partnership’s
overall exposure to credit risk in that its counterparties may be similarly
affected by changes in economic, regulatory or other conditions. The Partnership
mitigates potential credit losses in accordance with established credit approval
practices and limits by dealing primarily with counterparties it considers to be
of investment grade.
As of September 30, 2002, the Partnership’s credit risk is primarily
concentrated with the following customers: Con Edison, Niagara Mohawk and ISO,
all of whom are considered to be of investment grade. During the three months
ended September 30, 2002, the parent company of three of the Partnership’s
customers, all of whom are related parties, PG&E Energy Trading – Gas
Corporation (“PG&E Energy Trading – Gas”), PG&E Energy
Trading – Canada Corporation and PG&E Energy Trading – Power, was
downgraded below investment grade. The Partnership’s net credit exposure to
PG&E Energy Trading – Gas and PG&E Energy Trading – Power at
September 30, 2002 was approximately $0.1 million and $0.1 million,
respectively.
Accounting Principles Issued But Not Yet Adopted
In August 2001, the Financial Accounting Standards Board (“FASB”)
issued Statement of Financial Accounting Statements
(“SFAS”) No. 143, “Accounting for Asset Retirement
Obligations.” This statement is effective for fiscal years beginning after
June 15, 2002. SFAS No. 143 provides accounting requirements for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. Under the statement, the asset retirement
obligation is recorded at fair value in the period in which it is incurred by
increasing the carrying amount of the related long-lived asset. The liability is
accreted to its present value in each subsequent period and the capitalized cost
is depreciated over the useful life of the related asset. The Partnership is
currently evaluating the impact of SFAS No. 143 on its consolidated
financial statements.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections.” This statement eliminates the current requirement that gains
and losses on debt extinguishment must be classified as extraordinary items in
the income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS 145 eliminates an inconsistency in lease accounting by requiring
that modifications of capital leases that result in reclassification as
operating leases be accounted for consistent with sale-leaseback accounting
rules. The statement also contains other 46 nonsubstantive corrections to
authoritative accounting literature. The changes related to debt extinguishment
will be effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for transactions occurring after
May 15, 2002. The Partnership does not expect that implementation of this
statement will have a significant impact on its consolidated financial
statements.
18
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs
Associated with Exit or Disposal Activities,” which addresses accounting
for restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally Emerging Issues Task Force (“EITF”) Issue No.
94-3. This statement is to be applied prospectively to exit or disposal
activities initiated after December 31, 2002. SFAS No. 146 requires that the
liability for costs associated with an exit or disposal activity be recognized
when the liability is incurred. Under EITF No. 94-3, a liability for an exit
cost was recognized at the date of a company’s commitment to an exit plan.
SFAS No. 146 also establishes that the liability should initially be measured
and recorded at fair value. The Partnership does not expect that implementation
of this statement will have a significant impact on its consolidated financial
statements.
19
Regulations and Environmental Matters
20
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
21
ITEM 4. CONTROLS AND PROCEDURES
22
PART II. OTHER INFORMATION
Omitted from this Part II are items which are not applicable or to which the
answer is negative for the periods covered.
23
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
24
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
25
Critical Accounting Policies
Effective January 1, 2001, the Partnership adopted SFAS No. 133. This statement
requires the Partnership to recognize all derivatives, as defined in the
statement, on the consolidated balance sheets at fair value.
Legal Matters
The Partnership is a party in various legal proceedings and potential claims
arising in the ordinary course of its business. Management does not believe that
the resolution of these matters will have a material adverse effect on the
Partnership’s consolidated financial position or results of operations. See
Part I, Item 3 of the Partnership’s December 31, 2001 Annual Report on Form
10-K for further discussion of significant pending litigation.
On November 6, 2001, the Partnership received from the New York State Department
of Environmental Conservation (the “DEC”) the Facility’s Title V
operating permit endorsed by the DEC on November 2, 2001 (the “Title V
Permit”). The Title V Permit as received by the Partnership contains
conditions that conflict with the Partnership’s existing air permits, and
the Facility’s compliance with these conditions under certain operating
circumstances would be problematic. Further, the Partnership believes that
certain of the conditions contained in the Title V Permit are inconsistent with
the laws and regulations underlying the Title V program and Title V operating
permits issued by the DEC to comparable electric generating facilities in New
York. By letter dated November 12, 2001, the Partnership has filed with the DEC
a request for an adjudicatory hearing to address and resolve the issues
presented by the Title V Permit. The DEC has confirmed that the terms and
conditions of the Title V Permit are stayed pending a final DEC decision on the
appeal. Since November 12, 2001, the Partnership and DEC staff have engaged in
negotiations regarding the Title V Permit. At this time, the Partnership cannot
assess whether a settlement can be achieved, the likely outcome of the
adjudicatory hearing if no settlement is achieved, or the impact on the
Facility.
The Partnership is exposed to market risk from changes in interest rates,
foreign currency exchange rates, energy commodity prices and credit risk, which
could affect its future results of operations and financial condition. The
Partnership manages its exposure to these risks through its regular operating
and financing activities. (See “Market Risk”, included in Item 2,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations above.)
Evaluation of Disclosure Controls and Procedures
Based on an evaluation of the Partnership’s disclosure controls and
procedures conducted on October 21, 2002, the principal executive officers and
principal financial officers of JMC Selkirk, Inc., as Managing General Partner
of Selkirk Cogen Partners, L.P., and Selkirk Cogen Funding Corporation have
concluded that such controls and procedures effectively ensure that information
required to be disclosed by the Partnership in reports the Partnership files or
submits under the Securities and Exchange Act of 1934 is recorded, processed,
summarized, and reported, within the time periods specified in the SEC’s
rules and forms.
Changes in Internal Controls
There were no significant changes in internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) Exhibits
Exhibit No. Description
----------- -----------
10.5.16 First Amending Agreement dated as of the 1st day of November
2002, to the Second Amended and Restated Gas Purchase Contract
dated as of May 6, 1998 between Paramount Resources Ltd. and
Selkirk Cogen Partners, L.P.
99.9 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
99.10 Certification of John R. Cooper pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
99.11 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
99.12 Certification of John R. Cooper pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
(B) Reports on Form 8-K
Not applicable.
SELKIRK COGEN PARTNERS, L.P.
By: JMC SELKIRK, INC.
Managing General Partner
Date: November 14, 2002 /s/ JOHN R. COOPER
-------------------------------------
Name: John R. Cooper
Title: Senior Vice President,
Chief Financial Officer and
Treasurer
SELKIRK COGEN FUNDING
CORPORATION
Date: November 14, 2002 /s/ JOHN R. COOPER
------------------------------------
Name: John R. Cooper
Title: Senior Vice President,
Chief Financial Officer and
Treasurer
CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3 Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date
of this quarterly report (the “Evaluation Date”);
and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant’s auditors and the
audit committee of registrant’s board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant’s ability to record, process, summarize and
report financial data and have identified for the
registrant’s auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 14, 2002 /s/ P. CHRISMAN IRIBE
---------------------
P. Chrisman Iribe
President
JMC Selkirk, Inc.
Managing General Partner of Selkirk Cogen
Partners, L.P.
26
CERTIFICATION OF JOHN R. COOPER, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBINES-OXLEY ACT OF 2002
I, John R. Cooper, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date of
this quarterly report (the “Evaluation Date”); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant’s auditors and the
audit committee of registrant’s board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant’s ability to
record, process, summarize and report financial data and have
identified for the registrant’s auditors any material weaknesses
in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 14, 2002
/s/ JOHN R. COOPER
-------------------------------------------
John R. Cooper
Senior Vice President, Chief Financial Officer
and Treasurer
JMC Selkirk, Inc.
Managing General Partner of Selkirk Cogen
Partners, L.P.
27
CERTIFICATION OF p. CHRISMAN IRIBE, PRINICPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen Funding
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date of
this quarterly report (the “Evaluation Date”); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant’s auditors and the
audit committee of registrant’s board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant’s ability to
record, process, summarize and report financial data and have
identified for the registrant’s auditors any material weaknesses
in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesse.
Date: November 14, 2002
/s/ P. CHRISMAN IRIBE
---------------------------------
P. Chrisman Iribe
President
Selkirk Cogen Funding Corporation
28
CERTIFICATION OF JOHN R. COOPER, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John R. Cooper, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen Funding
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date of
this quarterly report (the “Evaluation Date”); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant’s auditors
and the audit committee of registrant’s board of directors (or
persons performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant’s ability to record, process, summarize and
report financial data and have identified for the
registrant’s auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 14, 2002
/s/ JOHN R. COOPER
--------------------------------------------------
John R. Cooper
Senior Vice President, Chief Financial Officer and
Treasurer
Selkirk Cogen Funding Corporation
29